The invention relates to stimulation of wells penetrating subterranean formations. In particular it relates to methods and compositions for the execution of multiple sequential well treatments and the temporary protection of previous treatments from subsequent treatments using a diversion technique.
Hydrocarbons (oil, condensate, and gas) are typically produced from wells that are drilled into the formations containing them. For a variety of reasons, such as inherently low permeability of the reservoirs or damage to the formation caused by drilling and completion of the well, the flow of hydrocarbons into the well may be undesirably low. In this case, the well is stimulated, for example using hydraulic fracturing, chemical (usually acid) stimulation, or a combination of the two (called acid fracturing or fracture acidizing).
Hydraulic fracturing involves injecting fluids into a formation at high pressures and rates such that the reservoir rock fails and forms a fracture (or fracture network). Proppants are typically injected in fracturing fluids after the pad to hold the fracture(s) open after the pressures are released. In chemical (acid) stimulation treatments, flow capacity is improved by dissolving materials in the formation.
In hydraulic and acid fracturing, a first, viscous fluid called a pad is typically injected into the formation to initiate and propagate the fracture. This is followed by a second viscous fluid that contains a proppant to keep the fracture open after the pumping pressure is released. Granular proppant materials may include sand, ceramic beads, or other materials. In acid fracturing, the second fluid contains an acid or other chemical such as a chelating agent that can dissolve part of the rock, causing irregular etching of the fracture face and removal of some of the mineral matter, resulting in the fracture not completely closing when the pumping is stopped. When confinement of the fracture geometry is required, the use of surfactant based fluids such as viscoelastic surfactants (VES) is recommended. Occasionally, hydraulic fracturing is done by pumping at very high rates a low viscosity fluid containing friction reducing polymers (i.e., slick water) to minimize the damage caused by highly concentrated polymers or the cost of other viscosifiers. In addition, to further minimize the damage, low viscosity surfactant based fluids can be utilized as slickwater treatments.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation, it is desirable to treat the multiple zones in multiple stages. In multiple zone fracturing, a first pay zone is fractured. Then, the fracturing fluid is diverted to the next stage to fracture the next pay zone. The process is repeated until all pay zones are fractured. Alternatively, several pay zones may be fractured at one time, if they are closely located with similar properties. Diversion may be achieved with various means. In the bridge plug technique (BPT), for example, the operator perforates, then fractures, then sets a bridge plug tool, and then repeats this process as necessary. This approach ensures 100% positive zone isolation by setting a packer between fractured and targeted zones. However, this approach is extremely costly. The costs come from extensive wireline service intervention, which requires additional time to perforate and to set and then retrieve the packer from the wellbore for each pay zone before and after a fracturing treatment. In addition, packer retrieval is sometimes risky.
In the flow through composite bridge plug (FTCBP) approach, which is a modification of the BPT, the FTCBP tool works as a BPT plug when there is higher pressure above it, such as during subsequent fracturing treatment. However, when the pressure is higher below the plug, such as when flowing the well back, the FTCBP lets fluid flow from below through the plug. Use of the FTCBP technique allows all preceding fractured zones to flow during completion of the well. This method has two advantages. First, it considerably reduces the shut-in time by flowing each fracture back early. Second, all previously treated zones help to clean up each new treatment. After a well is completed, the FTCBP can be drilled out easily or can be left in the well. This technique has proven to be a reliable tool that increases production. The main disadvantage is the cost and time needed to set the plug.
The sand plug technique (SPT) is similar to the BPT except that sand plugs are used instead of tools. The main idea is to fracture several pay zones sequentially via different perforation sets and set a sand plug at the end of each treatment stage to prevent flow beyond the plug, and thus divert the stress field for successive stages. This method substantially reduces time and costs because it requires no packer retrieval. However, due to initial in-situ stress variations, not all zones may be fractured. Furthermore, the proppant placement requires loading the wellbore with proppant, which may result in low efficiency of the treatment.
The limited entry (LE) approach, which is a simplified technique that does not require loading the wellbore with sand, makes the method more affordable. The method is used, for example, in combination with ball sealers to plug the stages, or by having differing numbers of perforations for the different stages. The LE method basically relies on creating an artificial pressure drop across a calculated number of perforations. From the number of perforations, the size of the perforations, and the injection rate, the pressure drop is calculated. This pressure differential is then adjusted through the number of perforations to create a designated pressure on the formation side of the perforations equal to the fracturing pressure. Knowing the exact fracturing pressure of each sand layer is an essential portion of the limited entry technique. In an infill-drilling program within a stratigraphic pay, the pressure of any given sand can vary considerably. Acquiring reliable pressure data involves testing each zone, adding time and cost to the completion. Without knowing the exact data, a treatment may result in little or no production from some sets of perforations.
Ball sealers usually comprise small rubber-coated balls suspended in the treating fluid and pumped into the well along with the treating fluid. The balls are carried down to the perforations communicating with the high permeability formation zone. The ball sealers seat on these perforations and divert the treating fluid to a formation zone having a lower permeability. In some cases, the presence of such ball sealers in the wellbore after the treatment presents operational problems during their retrieval. Use of degradable balls can help eliminate these problems, as reported in U.S. Pat. No. 6,380,138 to Ischy et al. Balls made of polyester degrade with time, forming soluble oligomers and allowing perforations to re-open.
The induced stress diversion technique (ISDT) is an application of staged hydraulic fracturing treatments without the use of any positive isolation, such as bridge plugs, frac baffles, sand plugs, or ball sealers. The ISDT combines the advantages of the LE and multi-staged fracturing techniques. With reference to FIG. 1, ISDT involves pumping multiple fracs in a well 10, e.g. first and second fractures 12, 14 in respective first and second pay zones 16, 18 stratified between non pay zones, and relying on the induced stress imparted by an earlier fracture stimulation to divert the subsequent fracture to the desired zone without positive zonal isolation. In this approach, the initial induced stress profile 20 from the first hydraulic fracturing stage 12 functions as input energy, together with the resulting induced stresses 22, to effectively divert the second stage 14 and subsequent fracs to the second pay zone 18 and successive stages. The ISDT procedure may be used to perforate and fracture multiple, discrete pay intervals by repeating the process as many times as needed. Some ISD techniques may include methods to induce screenouts to help with the diversion.
However, the ISDT requires good knowledge of reservoir properties. This makes ISDT not easily repeatable in areas with varying properties. To achieve maximum stress diversion, an optimized fracturing treatment is required based on mechanical properties of the formation. This often necessitates acquiring data using a design tool, such as a DataFRAC™ (Trade name of Schlumberger Technology Corp.), and successive redesigns of the approach. This takes time. In addition, redesign is strongly dependent on critical assumptions about formation properties. As a result, currently there is no reliable methodology to justify the use of ISDT in tight gas reservoirs. Therefore, there still exists a need for easy and reliable methods for diversion, multi-stage fracturing, or temporary sealing in the downhole environment.
Degradable materials have been used for fluid loss control and for diversion in the past. Examples include rock salt, graded rock salt, benzoic acid flakes, wax beads, wax buttons, oil-soluble resin material, etc. Degradable materials have been used in other downhole operations, such as disclosed in US 2006-0283591. However, these materials have generally been used in sizes, shapes and concentrations designed to build filter cakes on wellbore or fracture faces rather than to form consolidated plugs in wellbores, perforations, or fractures, e.g. under screen out conditions.